1. Field of the Invention
The present invention is related to rotary drilling of subterranean formations and, more specifically, to a rotary drill bit exhibiting particularly beneficial characteristics for drilling slow drilling shales as well as for high rate of penetration drilling.
2. State of the Art
Equipment used in subterranean drilling operations is well known in the art and generally comprises a rotary drill bit attached to a drill string, including drill pipe and drill collars. A rotary table or other device such as a top drive is used to rotate the drill string from a drilling rig, resulting in a corresponding rotation of the drill bit at the free end of the string. Fluid-driven downhole motors are also commonly employed, generally in combination with a rotatable drill string, but in some instances as the sole source of rotation for the bit. The drill string typically has an internal bore extending from and in fluid communication between the drilling rig at the surface and the exterior of the drill bit. The string has an outer diameter smaller than the diameter of the well bore being drilled, defining an annulus between the drill string and the wall of the well bore for return of drilling fluid and entrained formation cuttings to the surface.
An exemplary rotary drill bit includes a bit body secured to a steel shank having a threaded pin connection for attaching the bit body to the drill string, and a body or crown comprising that part of the bit fitted on its exterior with cutting structures for cutting into an earth formation. Generally, if the bit is a fixed-cutter or so-called "drag" bit, the cutting structure includes a plurality of cutting elements including cutting surfaces formed of a superabrasive material such as polycrystalline diamond and oriented on the bit face generally in the direction of bit rotation. A drag bit body is generally formed of machined steel or a matrix casting of hard particulate material such as tungsten carbide in a (usually) copper-based alloy binder.
In the case of steel body bits, the bit body is usually machined, typically using a computer-controlled five-axis machine tool, from round stock to the desired shape, including internal watercourses and passages for delivery of drilling fluid to the bit face, as well as cutting element pockets or sockets and ridges, lands, nozzle displacements, junk slots and other external topographic features. Hardfacing is applied to the bit face and to other critical areas of the bit exterior, and cutting elements are secured to the bit face, generally by inserting the proximal ends of studs on which the cutting elements are mounted into apertures (sockets) bored into the bit face or, if cylindrical cutting elements are employed, by inserting the substrates into pockets bored into the bit face. The end of the bit body opposite the face is then threaded, made up and welded to the bit shank.
The body of a matrix-type drag bit is cast in a mold interiorly configured to define many of the topographic features on the bit exterior, with additional preforms placed in the mold defining the remainder of such features as well as internal features such as watercourses and passages. Tungsten carbide powder and sometimes other metals to enhance toughness and impact resistance are placed in the mold under a liquefiable binder in pellet form. The mold assembly, including a steel bit blank having one end inserted into the tungsten carbide powder, is placed in a furnace to liquify the binder and form the body matrix with the steel bit blank integrally secured to the body. The blank is subsequently affixed to the bit shank by welding. Superabrasive cutting elements, also termed "cutters" herein, may be secured to the bit face during the furnacing operation if the elements are of the so-called "thermally stable" type, or may be brazed by their supporting (usually cemented WC) substrates to the bit face, or to WC preforms furnaced into the bit face during infiltration. Such superabrasive cutting elements include polycrystalline diamond compacts (PDCs), thermally stable polycrystalline diamond compacts (generally termed "TSPs" for thermally stable products), natural diamonds and, to a lesser extent, cubic boron nitride compacts.
During a typical drilling operation using such a rotary bit, drilling fluid is pumped from the surface through the internal bore of the drill string to the bit (except in a reverse flow drilling configuration such as is described in U.S. Pat. No. 4,368,787, wherein drilling fluid passes down the annulus and up the interior of the drill string). In conventional bits, the drilling fluid flows out of the drill bit through a crow's foot or one or more nozzles placed at or near the bit face for the purpose of removing formation cuttings (i.e., chips of material removed from the formation by the cutting elements of the drill bit) and to cool the cutting elements, which are frictionally heated during cutting. Both of these functions are extremely important for the drill bit to efficiently cut the formation over a commercially viable drilling interval. That is, because of the weight on bit (WOB) applied by the drill string necessary to achieve a desired rate of penetration (ROP) and the frictional heat generated on the cutters due to WOB and rotation of the bit, without drilling fluid or some other means of cooling the bit, materials comprising the drill bit and particularly the cutting elements attached to the bit face would structurally degrade and prematurely fail. Moreover, even if it were possible to cool the bit without drilling fluid but no means of removing the cuttings from the bit face was employed, the cutting elements (and the bit) would simply become balled up with material cut from the formation and would not be able to effectively engage and further penetrate into the formation to advance the well bore.
The need to efficiently remove cuttings from the bit during drilling has long been recognized in the art. Junk slots formed on the exterior of the bit body adjacent the gage of the bit provide channels for drilling fluid to flow from the face of the drill bit past the gage and to the annulus above, between the drill string and the side wall of the well bore, generally termed the well bore annulus. The pressure of the drilling fluid as delivered to the cutting elements through the nozzles or other ports or openings must be sufficient to overcome the hydrostatic head at the drill bit, and the flow velocity sufficient to carry the drilling fluid with entrained cuttings through the well bore annulus to the surface.
In a conventional bladed rotary drill bit, there may be a plurality of nozzles, each associated with one or more blades, the nozzles directing drilling fluid to cool and clean cutting elements of the blades. There may also be a plurality of junk slots, positioned between the blades and extending along the gage of the bit, to promote the flow of drilling fluid along each blade through its respective, associated junk slot. However, because the position and angular orientation of each nozzle is usually different relative to the centerline of the bit, and nozzle flow volumes may vary due to the hydraulics of the internal bit passages delivering the drilling fluid to the nozzles, the magnitude and orientation of flow energy of the drilling fluid will vary from one junk slot to the next. Consequently, because a relatively higher flow energy generates an adjacent zone or area of relatively lower hydraulic pressure in the manner of a venturi, drilling fluid emanating from a particular nozzle that would ideally flow past the desired cutting elements of a particular blade and up through the associated junk slot may actually be pulled or drawn downward and even laterally (circumferentially) across the exterior of the blade into a low pressure zone created by a fluid jet of another junk slot. In effect, some junk slots of conventional bits will have a positive or upward flow of drilling mud, while others will have a negative or downward flow resulting from thiefage of a part of the fluid flow by an adjacent junk slot flow zone and destruction of the desired, beneficial flow pattern in the junk slot from which the fluid is stolen. In addition, typical prior art bit designs include stagnant flow regions in and above the junk slots, usually adjacent, behind and above the blades where no appreciable drilling fluid flow, either positive or negative, occurs. These stalled or stagnant flow areas or "dead zones" may be the result of unexpected and undesired vortices that may enhance or even initiate negative flow in some junk slots, or may be the result of bad design which fails to recognize the effect of bit topography on flow of adjacent fluid. If such a disrupted flow pattern occurs, cuttings generated during the drilling process that would normally flow up through the annulus may circulate from a positive flowing junk slot to a negative flowing junk slot, or may accrete in place adjacent or above a blade, the result in either case, particularly at low flow rates, being bit balling as the cuttings mass increases. In other words, these recycling or stationary cuttings impede cutting efficiency of the cutters by obstructing access by the cutting elements to the formation. In addition, stagnant or reduced flow of drilling fluid results in less effective cooling of the cutting elements in those areas where the flow is impaired.
One arrangement to promote clearing of cuttings from a bit has been to position nozzles in the face of the drill bit to direct drilling fluid across the faces of the cutting elements to essentially peel cuttings from the cutting elements, as disclosed in U.S. Pat. No. 4,913,244 to Trujillo. U.S. Pat. No. 4,794,994 to Deane et al. discloses impacting the cutting elements with rearwardly directed fluid flow bounced off of the formation ahead of the cutting elements. Another solution, to remove cuttings from the cutting elements immediately after shearing from the formation by impacting them with a forwardly directed fluid jet from behind the cutting elements, is disclosed in U.S. Pat. No. 4,883,132 to Tibbitts. Such inventive structure is employed in the ChipMaster.TM. series of drag bits offered by Hughes Christensen Company. Another arrangement for directing fluid flow on the bit face, that of restricting fluid flow on the bit face and directing same through the use of spirally placed dams, is disclosed in U.S. Pat. No. 4,492,277 to Creighton. Yet another approach, to sweep the formation directly with fluid emanating from nozzles on the bit, is disclosed in European Patent Application 0 225 082 to Fuller et al.
In an attempt to more efficiently cut into the formation, variously-configured fluid courses have been devised, including those of U.S. Pat. No. 4,887,677 to Warren et al., which discloses a progressively widening diffuser that allows fluid to be flowed through a narrow throat of a fluid course in front of the cutting element and out a progressively widening diffuser, purportedly resulting in a significantly reduced pressure in front of the cutting elements. U.S. Pat. No. 4,245,708 to Cholet et al. discloses a junk slot having an upwardly directed nozzle placed in a venturi configuration to enhance the flow of drilling fluid through the junk slot. A similar arrangement is disclosed in U.S. Pat. No. 4,540,055 to Drummond et al. in the form of an air-drilling assembly, wherein upwardly aimed nozzles are placed on a sub above a rock bit between and parallel to vanes on the exterior of the sub.
It has also been recognized in the art that creating a flow vortex proximate the cutting elements may be desirable. For example, U.S. Pat. No. 4,733,735 to Barr et al. discloses a rotary drill bit having an exterior surface region adjacent the front surface of each blade and shaped to promote a vortex flow of drilling fluid across the cutting elements of that blade and partial recirculation of the drilling fluid before passage of same from the bit and up the annulus. Similarly, in U.S. Pat. No. 4,848,491 to Burridge et al., it is acknowledged that a bit may be configured to form a vortex to recirculate a portion of the drilling fluid directed into a junk slot by a nozzle.
One of the more elaborate methods and apparatus for removing drilling mud disclosed in U.S. Pat. No. 4,744,426 to Reed includes a downhole motor and "fan" that pulls the drilling mud from around the drill bit. Such a device, however, is a complex mechanical structure and adds to the cost of the drill string. U.S. Pat. No. 5,651,420 to Tibbitts et al., assigned to the assignee of the present invention and incorporated herein by this reference, also discloses a number of movable or dynamic structures for drill bits to assist with cuttings removal and bit cleaning.
U.S. Pat. No. 5,199,511 to Tibbitts discloses a unique bit configuration wherein the flow path from the bit interior to an area above the gage is located within the bit crown, the cuttings entering an interior flow area after being cut, then being swept upwardly by the drilling fluid.
U.S. Pat. No. 5,284,215 to Tibbitts discloses an enlarged and undercut junk slot for enhancing fluid flow, which structure extends upwardly into the bit shank area above the crown.
None of the aforementioned references, however, provide a structure and flow path directing and enhancing positive, independent flow of drilling fluid and entrained cuttings through all of the junk slots of a drill bit, substantially eliminating cross-flow and thiefage between junk slots and minimizing stagnant or dead flow zones in areas within and above the junk slots, which zones promote cuttings accretion and bit balling. Thus, it would be advantageous to provide a drill bit and other drilling-related structures with enhanced hydraulic characteristics affording such advantages.
One such solution to the above-mentioned problems is proposed by U.S. Pat. No. 5,794,725 to Trujillo et al., assigned to the assignee of the present invention and hereby incorporated herein by this reference. This patent provides a recirculation capability in a number of different embodiments, and bits according to the patent have been successful in reducing these problems, although the configuration of the bit, particularly in terms of optimizing its hydraulic design, is somewhat complex.
The aforementioned phenomenon of bit balling has become a more serious problem in recent years with the more widespread use of water-base drilling fluids. Traditional, oil-base drilling fluids have been used with some success for decades to help mitigate the problem of bit balling, but their use is becoming more limited because of environmental concerns. Further, oil-base fluids do not always prevent bit balling. Designing a bit to minimize balling has been, in the prior art, often attempted by using a low number of relatively tall blades carrying a relatively few, relatively large (such as 19 mm or .apprxeq.0.75 inch diameter) PDC cutters, and employing relatively deep (measured radially) junk slots. The low numbers of cutters and blades permits better focus of hydraulic energy, while the tall blades provide a greater standoff from the formation and thus increased spatial volume between the bit face and the formation face, and the deepened junk slots aid removal of formation cuttings past the side of the bit between the gage pads and up into the well bore annulus. It has recently been recognized, as disclosed in U.S. patent application Ser. No. 08/934,031 to Trujillo et al., now U.S. Pat. No. 6,125,947, assigned to the assignee of the present invention and hereby incorporated herein by this reference, that substantially balancing junk slot entrance areas and hydraulic flows associated therewith with formation cuttings volumes generated by blades associated with the respective junk slot hydraulic flows, and carefully apportioning (and in some cases balancing) the formation cuttings volumes between blades, can be beneficial in alleviating bit balling.
However, past work in the field has overlooked a significant characteristic of bit balling which has recently been recognized by the inventor herein: that bit balling originates or initiates at the gage of the bit and not on the bit face. Once the bit gage (i.e, a junk slot) is blocked, the mass of formation cuttings builds back down toward the bit face and onto the face, until the bit completely balls.
Taking into consideration all of the recent improvements offered by the assignee of the present invention, there still remains a substantial, long-felt need in the industry for a rotary drag bit which is substantially resistant to bit balling in plastic formations, and which is capable of achieving a relatively high rate of penetration (ROP) even in normally difficult, slow-drilling formations, such as shales.